IR 05000219/1987022

Insp Rept 50-219/87-22 on 870619-0809.No Violations Noted. Major Areas Inspected:Plant Operations,Radiation Control, Physical Security,Surveillance & Maint,Followup of Causes for Reactor Trip

ML20235K895
Person / Time
Site:	Oyster Creek
Issue date:	09/25/1987
From:	Blough A NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20235K856	List: IR 05000219/1987022 ML20235K854
References
50-219-87-22, NUDOCS 8710050268
Download: ML20235K895 (21)

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l U.S. NUCLEAR REGULATORY COMMISSION j REGION I Report N /87-22 Docket N License N DPR-16 Priority --

Category C Licensee: GPU Nuclear Corporation 1 Upper Pond Road Parsippany, New Jersey 07054 Facility name: Oyster Creek Nuclear Generating Station Inspection Conducted: June 19 - August 9, 1987 Participating Inspectors: W. H. Bateman W. H. Baunack J. F. Wechselberger Approved By: /[Me[

A.' R. Sitiugh, Chief 7- W 67 Date Reactor Projects Section IA, DRP Inspection Summary:

Routine inspections were conducted by the resident inspectors and one Region -

based inspector (319 hours0.00369 days <br />0.0886 hours <br />5.274471e-4 weeks <br />1.213795e-4 months <br />) of activities in progress including plant opera-tions, radiation control, physical security, surveillance, and maintenanc The inspectors also followed up the causes for a reactor trip, reviewed com-pleted modification work, completed inspections related to Region I Temporary Instructions, participated in a tour of the site by Commissioner Carr, updated on the status of temporary variations, and reviewed periodic and special re-port In addition, the inspectors questioned the licensee on several Core Spray system issues, inadvertent placement of a step ladder that restricted operation of a reactor building to torus vacuum breaker valve, feed water regulating valve positioning problems, and operability of a Reactor Building j Closed Cooling Water system containment isolation valv Additionally, the 1 inspectors itemized a list of observations made by the Region I Regional Administrator and gave the list to the licensee. This list is included as an q enclosure to this repor The inspectors were also updated by the licensee >

regarding progress of the Technical Functions Self-Assessment effort Results:

No violations were identified. Follow up of the causes into partially blocking  !

a reactor building to torus vacuum breaker reinforced the NRC's concern that l plant personnel do not understand or appreciate the safety significance of l these valve I t

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j DETAILS I 1. Plant Operation Review i

1.1 The 0yster Creek maximum drywell bulk air temperature has been 1 increased from 135 F to 150 F. The staff has found this higher )

temperature limit to be acceptable provided that if the temperature reaches 150' F or greater, an 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> time limit be established to get <

the drywell bulk - temperature below 150 F or to shutdown. 'The inspector reviewed the high drywell temperature. alarm response pro-cedure (setpoint 140 F) to verify required operator action if the .

temperature reached 150 F. The procedure requires the operator to - -) '

enter Procedure EMG-3200.02, Primary Containment Control, and to commence an orderly plant shutdown in accordance with plant proced-ures if the drywell bulk temperature cannot be reduced to below q 150 i i

1.2 Section 4.22.2 of the Integrated Plant Safety Assessment Report dis- J cussed lines penetrating containment with only remote manual isola- J

. tion valves. Operator action .is required to isolate such lines if a significant. leak or break occurs. The staff considers the licensee's means to detect the need to isolate these lines and the location from which these valves can be operated to be adequat During this inspection, the inspector verified that the licensee has revise j plant procedures to include operator actions for line. isolatio Plant procedure 2000-0PS-3024.05, Containment Spray System -

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Diagnostic and Restoration Actions, Step 3.5, describes action to be 1

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taken in response to a containment spray system line break, and plant procedure 2000-0PS-3024.17, Core Spray System- Diagnostic and Restoration Action, Step 3.7, describes action to be taken in j response to a Core Spray system line brea '1 1.3 The licensee has determined that both the Generic NRC staff safety '

evaluation and the Boiling Water Reactor Owners Group evaluation which conclude that BWR purge and vent lines of 2 inches in diameter or less need not be provided with a containment high radiation isola- 1 tion signal are applicable to Oyster Cree The licensee further 1 determined these 2 inch containment vent and purge valves can be j verified closed by the control room operators within 30 minutes in j response to a containment high radiation alar The inspector i reviewed the Containment High Radiation Alarm Response procedure to j assure that it required the operators to verify the closure of the j small containment vent and purge valve j l

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1.4 In the past, the licensee has experienced problemsL with the Main Steam line drain valves leaking (valves V-1-106, V-1-107, V-1-110 and V-1-111). These valves serve as containment isolation valves. In

- order to prevent leakage through the valves when they are not in use, spectacle flanges have been installed in series with the isolation valve During this inspection, the licensee's control of these spectacle flanges was reviewed. The use of these valves has been incorporated into Station Procedure 301, Nuclear Steam Supply. Syste l This procedure provides instructions for rotating the spectacle j flanges on the main steam drain lines to the open position prior to

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draining the main ~. steam lines and again rotating the flanges to the closed position when the draining is complet . Review of Modifications Certain aspects of modifications performed by the licensee and reported as required by 10 CFR 50,59 were reviewed as follows:

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Modification performed under B/A No. 402740, DC Power Supply to Emergency Isolation Condenser Valves. This modification replaced cables to several valves with la rger cables to compensate for excessive. voltage drops. The modification as originally installed was not designed to meet .the requirements of 10 CFR 50 Appendix During this inspection, the licensee verified this modification has been upgraded to meet Appendix R requirement Modification performed under 8/A 402052, Containment Pressure, Torus Water Level and Hydrogen /0xygen Monitoring System. Included in this modification was a drain connection to the bottom of the torus at bay 20. This drain connection was provided for the complete draining of the torus. The installation and control of this new containment penetration was reviewed. The torus drain connection was installed from the bottom of the torus by removing an existing drain plug and installing a normally closed manual isolation valve and a threaded cap to provide double isolation. Procedural control of the valve and cap have been provide The inspector had no further questions relative to these modification . Reviews Required by Temporary Instructions Inspections required by several Temporary Instructions were conducted during this inspection as follows:

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Temporary Instruction. 2515/82, Inspection' Requirements for IE Compliance Bulletin 86-01, " Minimum Flow Logic Problems that Could Disable RHR Pumps." .The- licensee's response to Bulletin 86-01 describes the minimum flow protection which is provided for the Core Spray system, the only emergency core cooling system which incor-porates minimum flow provisions at Oyster Creek. Oyster Creek does not have the RHR system described in the Bulletin. A review of the licensee's response shows that the concerns discussed in the Bulletin are not applicable to Oyster Cree Region I Temporary Inspection Instruction No. RI-86-01, " Inspection of Standby Gas Treatment System." This instruction described a design deficiency identified at another facility in which a single failure rendered the Standby Gas Treatment system incapable of per-forming its design functio The failure was associated with a damper in the cross-tie which provided an approximate twenty-five percent cooling flow and a failure of a temperature sensor on the fire suppression system for the charcoal be The Oyster Creek design is not susceptible to this single failure since cooling ficw is provided to the idle filter through individual purge valves pro-vided for each train. These purge valves and associated orifices limit cooling air flow to 50 CFM. Also, there are no temperature-sensors or fire suppression system installed at Oyster Cree Region I Temporary Inspection Instruction No. RI-86-02, " Inspection -

of General Electric Type AK-F-2-25 Breakers." This instruction describes certain failures which have occurred in GE Type AK-F-2-25 breakers. The instruction also requires inspectors to make certain determination These determinations and findings are as follows:

Are GE Type AK-F-2-25 breakers used in important-to-safety applications?

There are no AK-F-2-25 breakers used in important-to-safety functions at Oyster Creek. However, other GE Type AK breakers are used on various systems. The licensee is aware of GE SIL No. 448 describing the maintenance and lubrication for Type AK breakers and has factored SIL recommendations into the existing maintenance progra Results of a review performed by the licensee as a result of NRC Information Notice 87-12 show there has never been a failure to close or a failure to trip due to breaker binding or lubricatio How is the ATWS RPT function accomplished and what is the '

maintenance / testing performed and what problems have been experienced?

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The ATWS RPT function is provided by- the tripping of the recir-culation . pump M-G motor breakers. These breakers are GE type AM-4.11-250-7 A review of the maintenance history for these breakers since 1983 shows there has been no failure of the breakers . to open during this period. The breakers are on a refueling cycle PM and each has been rebuilt by GE during the past five year Region I Temporary Instruction 87-03, Bypass of Non-Essential Diesel Generator Trips. This instruction described a potentially generic issue wherein emergency diesel engine non-eusential protective trips are not bypassed on loss of power (dead bus) conditions. Inspection results indicated:

(1) - For a LOCA none of the non-essential emergency diesel generator (EDC) trips are bypassed. When a LOCA signal is received (con-tainment high pressure and reactor low water level), the EDG l starts and idle When a loss of offsite power occurs, the EDG receives a fast start signal which bypasses all trips except differential fault, crankcase overpressure, and overspee .(2) The Automatic Actuation Test, 636.2.001, is performed every 18 month This is a loss of offsite power test. It verifies that all bypass features function with the exception of the following l relays that were installed during the recent 11R refueling out-i

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age and have bypass contacts keyed off the safety-related 4160V breakers:

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Leading bars Reverse power The procedure is presently being revised to include verification that the bypass contacts function properl . Blocking of Reactor Building-Torus Vacuum Breaker at Oyster Creek Nuclear Generating Station l

On July 16, 1987, at approximately 1230, the Operations Manager discovered 1 a six foot stepladder blocking the reactor building-to-torus vacuum I breaker from opening completely. The counterbalance arm for the mech- I anical vacuum breaker V-26-15 was found positioned between two ladder rungs, thus limiting the opening capability of the vacuum breake The

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Operations Manager, while touring the plant, discovered the ladder and

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pr9mptly removed it. The licensee determined that the valve would have

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opened approximately 50% prior ' to the counterbalance arm contacting the 1 l stepladde (The counterbalance arm is connected directly to the disc hinge pin and is used during surveillance testing to verify- valve opera- ,

bility.)

The licensee determined that the ladder was positioned by contractors l performing radiography testing in this area of the plant. The contractors were performing these tasks for the plant Quality Control Group to deter-mine the position of the Core Spray System II booster pump bypass check valv Interviews of involved personnel after identification of the i problem disclosed that plant quality control personnel were aware of the sensitivity of the vacuum breaker valve and were very careful not to hit l the counterbalance arm. This sensitivity was misdirected, however, l because of a lack of understanding of valve operabilit Licensee estimates of the start of work in this area indicated the valve was restricted from 100% operation at approximately 1800 on July 15, 1987.

l This represents reduced reactor building-to-torus flow in the event of a LOCA for a maximum time of approximately 18 hour2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br /> The significance of the reduced flow capacity is minimal and amounts to degradation of' a redundant system. The Technical Specification basis describes the vacuum relief system as "...two 100% vacuum relief breaker l subsystems (2 parallel sets of 2 valves in series)." In addition,

" Operation of either subsystem will maintain the containment external pressure less than the external design pressure of the drywell by 2 psi; the external design pressure of the suppression chamber is 1 psi." For clarity, the two parallel mechanical vacuum breakers (V-26-17 and V-26-15)

are in series with two parallel pneumatically operated vacuum breakers (V-26-18 and V-26-16). The available flow capacity would have been in excess of the required 100% design flow. Thus, the Technical Specifica-tion basis was satisfied assuming no single failure. However, Technical Specification 3.5.A.4 requires, in part, " ..two reactor building to suppression chamber vacuum breakers in each line shall be operable at all times when primary containment integrity is required." Therefore, Tech-nical Specifications may have been violated in that, based on a single failure in the unaffected line, the line with the blocked valve may not have been able to pass full flo However, the Technical Specifications provide for a- 7 day LCO action statement with one train inoperable. The licensee is currently attempting to determine the valve's flow capacity in the restricted conditio This event is mitigated, however, by the facts that the licensee (1) self-identified and corrected the blockage within 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br />, (2) promptly re-ported the event to the resident inspectors and made the appropriate ENS notifications, and (3) was well within the 7 day LC0 action statement with one inoperable reactor building-to-torus vacuum breaker. However, this event reinforces NRC concern as discussed in Inspection Report 50-219/

87-16 and associated Enforcement Action EA 87-92 (August 24,1987) that the licensee has not achieved a sufficiently widespread appreciation and understanding of the importance of the vacuum breaker _ _ _ _ - _ - - _ _ _ _ _ _

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l ~5. Regional Administrator Tour The Regional Administrator visited Oyster Creek Nuclear Generating Station )

on June.23, 1987 for a plant tour (accompanied by a representative of i plant management and by a resident inspector) and management discussion )

During the inspection tour, the Regional Administrator noted the following j discrepancies:

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Missing conduit cover (5' behind auto DC transfer switch').

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) l 2) HVAC vents starting to get clogged due to lack of cleanin .

3) U-clamp restraint missing on conduit on floor near south wal ) Debris . scattered around room appears to be fire break foam used in penetrations. Other debris from maintenance activities-also presen ) I cable decommissioned in place; should be taped and tagge !

"C" Battery Room 1) Battery level above maximum level indicated on battery cells. Cells don't appear to be level as acid leakage occurs at one corner of cell while at other corner leakage is not apparen ;

2) Loose material under batteries; should be clean to' detect battery  !

leakag j 3) Residue from cleaning solution or battery acid present on Uni stru ) Drain in battery room appears to be plugge Southwest Corner Room (Rx Building EDT)

1) 011 can present next to spare RBEDT pum ) Spare RBEDT pump present in roo ) 2 ladders leaning against wall in upright position. One apparently j to inspect pipe support approximately 20 feet from grating, other ladder only 10 feet hig ) Recirculation pump conduit leak coming from under turbine building sla ,

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5) General debris in room from maintenance activitie ) Nails on room coole ) Bucket present in room to catch recirculation pump conduit leakage overflowing -onto floo Should use " pocket" to catch leakage and funnel to floor drain to avoid contamination sprea ) Lower louvers on core spray motor dusty / dirty; upper louvers bette ) Unused fire hose hanging down from penetration into torus roo Control Room 1) Ceiling tiles appear that they may fall onto control panels during seismic event repositioning switche Present ceiling tile clamps may not prevent thi Licensee should addres Shutdown Cooling Room 1) Debris in area; does not appear to be related to ongoing wor ) Lots of dirt presen ) Protective clothing bag overflowin ) Electrical cable hung over railing is crackin RK02 Rack 1) Packing leaks behind panel; collection bags need to be positioned to catch leak ) Root valves have missing handwheels and, as a result, have been operated by wrench, scoring the This has resulted in packing leak ) Table near RK02 rack should be restrained from movemen #1 Emergency Diesel Generator 1) General debris including light bulb and tap ) Cabinet access panel bolts not completely screwed in; inside diesel enclosure ski ) Label missing from gauge inside diesel enclosur _-___ _ _ _ _ - _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - - - _ _ - _ - _ _ _ _ _ - - _ - - - - - - - - - - - - - - -

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4) Wire exposed coming out of limit switch adjacent to governo ) Lower starting gear teeth may be wor ) Good job labelin ) Cigarette butt in engine en ) No mark on speed droop settin ) Is governor oil different viscosity between winter and summer?

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1) Suggest use of rubber boot on snubbers to protect piston rod.

-2) Gum wrapper on containment spray pump in drip housing between pump and motor (NE Corner Room).

3) Rag in speaker; speaker pointed upwards (SE Corner Room).

4) Electrical cable tray on 75' near 119' access bay opening has debris; tray runs in N-S directio ) Keep and eye on shear cracks on 75' elevation N-S beam. May be seen from NW stairwell going from 75' to 51'.

At the completion of his tour, the Regional Administrator briefed plant management in the presence of the NRC Senior Resident Inspector and Projects Section Chief. He indicated that the plant appearance had vastly improved since the 1980-81 timeframe. However, continued attention by the licensee is needed to ensure that the licensee's own organization aggress-ively identifies and corrects, as they develop, conditions such as those noted in the Regional Administrator's tou Subsequent to the tour, the Senior Resident Inspector provided the above list of comments to the licensee for resolutio . Review of Plant Modifications The licensee reported a number of facility modifications which were made in accordance with the requirements of 10 CFR 50.59. One of these modif-ications was reviewed during this inspection. The modification which was reviewed was the addition of containment spray pump suction pressure gauges. The principle documents associated with this modification which were reviewed are the Nuclear Safety / Environmental Impact Evaluation Summary Sheet, Safety Evaluation No. 402672-001, and the Division I System Design Description SDD 241A, Containment Spray Pump Suction Pressure Gauge ..

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,~ g The purpose of this modification is to provide pressure gauges on the suction side of each of the containment spray pumps. This will allow pressure readings to be taken during the. surveillance testing of the con-tainment spray syste During the review of the Division I System Design Description (SDD),

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several requirements were identified in the SDD which appeared not to have i been reflected in facility procedures or to have been changed in the SD '

.l These-requirements are identified as follows: j Section 3, Function and Design Requirements, states, "The new pressure gauges shall be used only during surveillance testing and not during con- !

tainment spray system initiation for accident mitigation." Section 3.2.3, i System configuration and Essential Features, states, "Normally closed isolation valves shall be provided for the test system when not being used for surveillance testing..."

These requirements .were determined not to have been incorporated into facility procedure In the valve lineup portion of Station Procedure 310, Containment Spray System, it is required that the isolation valves - 'l for the test system (valves V-21-103, V-21-104, V-21-105, and V-21-106) . i be maintained open during normal operation. In addition, the Containment Spray and Emergency Service Water System P & ID has been revised to show these isolation valves as normally ope The failure to operate the containment spray suction pressure gauge modif-ication in accordance with the SDD was resolved, however, by a memo from a plant engineer to a Tech Functions engineer dated May 21, 1984 that specifically stated that a revision was made to the Containment Spray )

system operating procedure to align the root and isolation valves in the open position. The inspectors had no further questions on this issu In this instance, the change from the SDD description of how the modifica- l tion is to be operated and the way it is actually operated has relatively little safety significance since the gauge lines involved are only 1/4 inch lires. However, the practice of deviating from the technical docu-ment wh1ch describes the operation of a system installed in the plant could have significant consequences if permitted to occur under different circumstance . REOS Low Level Instrument Downscale Failure On June 16, 1987, RE05B, a low reactor vessel water level instrument, failed downscale causing a half scra The licensee determined that the failed instrument resulted from a transmitter proble The transmitter was bench tested and found to have a defective sensor element (capacitor sensing element shorted). Rosemount, the transmitter vendor, had earlier reported transmitter problems that demonstrate an intermittent syndrom l ll

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The syndrome is characterized by an instantaneous output signal shift, off scale (28 mA or 2.8 mA low) which continues until it is corrected by one of a number of means. The licensee did not attempt to troubleshoot the defective transmitter installed, but instead removed it and performed bench testing in the laborator The testing determined that the failure did not exhibit the same characteristics as previously reported by the vendor. Rosemount concurred with the licensee determination and requested the transmitter for inspectio The licensee plans to send the trans-mitter to Rosemount for examination. None of the other similarly installed Rosemount transmitters have experienced any problems. The inspector had no further concerns on this matte . Commissioner Carr Visit Commissioner Carr visited Oyster Creek on July 14, 1987. The licensee made extensive presentations to the Commissioner describing their main-tenance program and conducted a tour of the plant and maintenance facilitie .

, "C" Feedwater Regulating Valve Failure l

On July 9, the plant experienced a feedwater transient resulting from a failure of the "C" feedwater regulating valve (FRV). The operators took prompt corrective action to avoid a reactor trip and stabilized the plant at approximately 65% reactor power. The inspector questioned what main-tenance had been performed on the "C" FRV. The licensee determined that maintenance had been performed on the positioner during the last outage and that the connecting rod between the positioner and the hydraulic snubber did not have full thread engagemen After operating the "C" FRV for a period of time, the few threads that were engaged broke, thus free-ing the positioner from the hydraulic snubber and resulting in the "C" feedwater pump tripping at 100% power. The inspectors attended the licensee's post trip review and determined the review to be thorough. The licensee replaced the "C" FRV positioner and radiographer the "C" posit-ioner to ensure the positioner connecting rods had full thread engagemen The inspector questioned if A & B FRV had similar maintenance performed on them and if potentially the same problem could exist based on discussions at the post trip review concerning minute flow oscillations indicated by the computer printouts. The licensee radiographer the A & B FRV positioner connecting rods and found them to have full thread engagement and to be in satisfactory conditio . Core Spray System II Low Flow On July 10, Core Spray System II failed a technical specification surveil-lance test on low flow and the system was declared inoperable. The sur-veillance acceptance criteria for minimum Core Spray System II flow is 3640 gpm; test results were 20 gpm lower. The licensee examined other system parameters and determined that the reduced flow must have resulted from a flow restriction in the full flow Core Spray test line. Recently,

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due to water hammer concerns, the licensee .had been slowly opening the full flow test valve to reduce pipe oscillations resulting from a complete immediate stroke of the test valve. (See NRC Inspection ' Report 87-13, paragraph 9.) The licensee theorized that as a result, the check valve in the test'line may not be opening completely since the valve was no longer subject to the immediate dynamic force as in the past. A series of radiography tests were performed on the cneck valve at various orienta-tions and flow conditions and on the flow restricting orifice present in the test line. These efforts provided little information with regard to explaining the cause of the reduced flow. After completing this portio of their investigation, the licensee performed another surveillance test using a milliammeter to obtain flow reading directly from the flow instru-ment. This test yielded acceptable results with regard to satisfying the technical specification flow criteria, but was not obtained using installed system flow meters nor had the previous system flow degradation been ade-quately explained. The inspectors requested the licensee to continue their investigation and to perform the monthly surveillance on a weekly ,

basis. The licensee agreed to perform the additional tests and declared  !

the system operable on 7/16/87. The licensee continued to perform the weekly surveillance until a forced outage commenced 'on 7/30/87 and the restricting orifice was removed from the full flow test line. Subsequent surveillance have met the Technical Specification requirements. The j licensee plans to further inspect system components to determine the cause '

of the system flow drop at the next opportunity. These components will include the check valve around Core Spray System II booster pumps, the i

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motor operated test valve and the full flow test line check valv . Power Reduction Caused by Grass Blockage at Intake Structure On June 24, 1987, at approximately 2300 the facility experienced a grass j deposition at the intake structure resulting in a power reduction to approximately 50%. The grass had been coming into the intake canal from the Barnegat Bay during the previous days, but the 6/24/87 occurrence was the worst. The licensee had stationed personnel at the intake structure for grass removal anticipating additional grass deposits but not quite as large as this. The grass resulted in breaking the shear pins on the three south side screens and collapsing the racks on the number three dilution pump. The licensee operators had to secure the south side circulation and service water pumps and reduce power to prevent further damage. The inspectors reviewed the licensee's actions and questioned the licensee to j determine if south side emergency service water pumps had sufficient

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height of water for proper net positive suction head if the pumps should be required. The inspectors were satisfied with the licensee's response and determined that the shif t personnel had performed well in keeping the

, plant safely at power and in minimizing the damage at the intake

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12 Emergency Service Water System Inoperable On July 15, Emergency Service Water (ESW) System II 52C and 52D pumps were declared inoperable as a result of measured high flow above the action range during a surveillance tes The licensee determined that the throttled common discharge butterfly valve, V-3-87, had been repositioned allowing increased system flo The licensee had previously decided to throttle V-3-87 to maintain ESW system pressure higher than containment system (CS) pressure. This was done to satisfy a NRC concern that in the event of loss of coolant accident coupled with containment spray heat exchanger leakage, radionuclides could be dispersed to the environmen Therefore, V-3-87 has been throttled to achieve this positive ESW/CS differential pressur The licensee repositioned V-3-87, and repeated the surveillance test with acceptable results. The inspectors reviewed the test results and found them to be acceptable. A decision was made to change the surveillance test to avoid the need to rebaseline system flow nearly each time the test is performed. The change involves throttling the valve to achieve a flow value and measuring changes in other monitored parameters to verify operabilit . Licensee Action on Previous Inspection Findings (Closed) Unresolved Item (219/87-04-04): Licensee to develop procedure to disposition dropped fuel assembly and to conduct a record to verify no other assemblies have been dropped in the pas The inspectors witnessed portions of the removal of the broken fuel bundle reported in NRC Inspection Report 87-04 and further discussed in 87-1 The licensee completed disassembly and positioning of a broken fuel bundle on July 9, 1987. The fuel bundle was placed in a fuel canister in a spent fuel pool storage location. The inspectors found the procedure and opera-tion to be adequately performed. In addition, the licensee reviewed fuel accountability documentation to determine that UD3E, the broken fuel assembly, is the only fuel assembly that has been dropped at the Oyster Creek facilit .(Open) Violation (219/87-13-02): Failure to Hydrostatically Test A New Weld for Valve V-2-11 in the Feedwater System During the short maintenance outage that occurred during this report period, the licensee performed a pressure test on V-2-11 in an attempt to meet the intent of the ASME Section XI Cod On August 3, 1987, a press-ure test at 1.1 times design pressure was performe Inspection of the new weld on the reactor vessel side of V-2-11 indicated no leakag The test pressure obtained was 1470 psig and the required hydrostatic test pressure was 1370 psig. The other aspects of the violation remain open pending receipt of the licensee formal response to the violation and sub-sequent NRC follow-u . _ _

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14. Review of Periodic and Special Report Upon receipt, periodic and special reports submitted by the licensee pur-suant to Technical Specification requirements were examined by the inspector This review included the following considerations: the report includes the information required to be reported to the NRC; planned' corrective actions are adequate for resolution of identified problems; and the reported information is vali The following reports were reviewed:

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Monthly Operating Reports for April, May, and June 1987;

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A preliminary report was made by the licensee by letter dated 7/13/86 documenting inoperability of the fire suppression water system on July 10, 198 This preliminary report preceded a full report as required by paragraph 3.12.8 of the Tech Specs. The report documen-ted that a post indicator valve (V-9-33) cracked between its flange and body and caused a loss in system pressure. Fire watches were established in all affected areas and the valve was replaced and the system returned to service on July 13, 198 . Radiation Protection During entry to and exit from the RCA, the inspectors verified that proper warning signs were posted, personnel entering were wearing proper dosimetry, personnel and materials leaving were properly monitored for radioactive contamination, and monitoring instruments were functional and in calibratio Posted extended Radiation Work Permits (RWPs) and survey )

status boards were reviewed to verify that they were current and accurat The inspector observed activities in the RCA to verify that personnel complied with the requirements of applicable RWPs and that workers were  ;

aware of the radiological conditions in the are l No violations were identifie l

i 16. Updated Status of Temporary Variations )

NRC Inspection Repor.t 87-16 detailed problems with the Temporary Variation j process that contributed to the improper tying open of two torus to dry- l well vacuum breaker valve Prior to this event and restart from the 11R  !

outage during the licensee's readiness for restart review, 65 Temporary  !

Variations had been targeted for action in an effort to reduce the large j number. Of those 65, 36 received some type of action and 29 remained open. Of the 36 that received action, 5 were removed,13 were closed but l were actually entered into the Field Change Notice (FCN) process, and 18 l were closed but were actually transferred onto Short Form :

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The' fact that a number of Temporary Variations in actuality still existed but had been transferred to another type of tracking document, was realized during this report period. The statement was made in NRC Inspec-tion Report 87-16 that all open Temporary Variations had received a safety review prior to restart did not include the 18 of 36 that did not enter the FCN process. The licensee informed the NRC inspectors that of these 18, one was superseded by a new Temporary Variation and received a safety review and the remaining 17 that had been transferred to Short Forms, all received safety reviews. Of these 17,16 have been incorporated into the FCN process to make them pertranent and one, a turbine bui.lding supply fan jumper, is being addressed by the LER proces The inspectors questioned the licensee as to the possible existence of any 1 other mechanisms whereby open Temporary Variations could have been trans-ferred to another tracking system and not have received a proper safety evaluation. The licensee stated all previously open Temporary Variations have been accounted for and received a safety evaluation if required. The inspectors had no further question 'i 17. Observation of Physical Security During daily tours, the inspectors verified that access controls were in accordance with the Security Plan, security posts were properly manned, protected area gates were locked or guarded and that isolation zones were free of obstructions. The inspectors examined vital area access points to veri fy that they were properly locked or guarded and that access control was in accordance with the security pla On July 10, 1987, at approximately 0600, a member of plant management I discovered a security guard apparently asleep at the main gate security I building. The guard's post was located outside the protected area and other security force personnel were present in the area. Therefore, plant security was not a concer The licensee investigated the event and determined to release the individual from employmen The inspectors requested to be informed if any other similar events occurred in the futur j No concerns were identifie l 1 Plant Operation Review l l

18.1 Routine tours of the control room were conducted by the inspectors '

during which time the following documents were reviewed: ,

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Control Room and Group Shift Supervisor's Logs;

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Technical Specification Log; j

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Control Room and Shift Supervisor's Turnover Check Lists;

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Reactor Building and Turbine Building Tuur Sheets;

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Equipment Control Logs;

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Standinq Orders; and,

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Operational Memos and Directive .2 Routine tours of the facility were conducted by the inspectors to make an assessment of the equipment conditions, safety, and adherence to operating procedures and regulatory requirements. The following areas are among those inspected:

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Turbine Building

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Vital Switchgear Rooms

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Cable Spreading Room

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Diesel Generator Building

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Reactor Building The following additional items were observed or verified: Fire Protection:

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Randomly selected fire extinguishers were accessible and inspected on schedul Fire doors were unobstructed and in their proper positio Ignition sources and combustible materials were controlled in accordance with the licensee's approved procedure Appropriate fire watches or fire patrols were stationed when equipment was out of service, Equipment Control:

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Jumper and equipment mark-ups did not conflict with Technical Specification requirement Conditions requiring the use of jumpers received prompt licensee attentio Administrative controls for the use of jumpers and equip-ment mark ups were properly implemente _ _ _ - _ - _ - _ _ - - _

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Plant housekeeping .and cleanliness were in accordance with approved licensee program '

No inspector concerns were identifie .

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19. Technical Support Division Self-Assessment j i

NRC Systematic Assessment of Licensee Performance (SALP) Report N '

50-219/85-98 recommended that the technical support groups within GPUN perform a self-assessment in an attempt : to determine the reasons for l- inconsistent performance. During this report period, representatives - from i

the Plant Engineering and Technical Functions groups updated the NRC inspectors as to the status of their self-assessment efforts. The assess-ment is divided into four phases, the first phase to be' complete in August l 198 Phase IV, which involves' documenting the assessment results and l developing a corrective action plan, is scheduled for completion in '

October 1987. The inspectors felt the overall plan to perform the assess-ment could result in successful identification of the problem areas. The inspectors will continue to follow licensee progress both with the first four phases' and subsequent implementation of the corrective action pla . Review of Key Operational Events During this report period, the following key operational events occurred and were followed up by the inspectors:

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At about 0500 on July 30, 1987, a reactor scram occurred as the result of a high reactor pressure signal caused by the inadvertent closure of outboard main steam isolation valve (MSIV) NS-04A. The sequence of events started during routine MSIV closure testing about one half hour earlier. When NS-04A was tested, the valve traveled to the 10% closed position in about 3 seconds which is a substantially shorter time than normal. About the same time a low air pressure alarm was received. The operators very quickly determined that an air leak ' existed and, based on the inability to fully reopen NS-04A, commenced to reduce power in anticipation of NS-04A going fully closed. While reducing power, an investigation into the location of the air leak determined it was associated with the NS-04A air oper-ator and NS-04A went fully closed, thus causing the high pressure signa I

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The subsequent investigation into the cause of the problem determined that the 3-way valve used to direct air to open the MSIV and bleed off air to allow the valve to slowly close for testing purposes, became separated from the valve manifold block. The air operating mechanism for the MSIV consists of a large aluminum block with var-ious holes and ports machined in i To this aluminum block are attached castings also with various holes and ports that, when fastened to the b?ock, form the complete manifold. h the case of the NS-04A 3-way valve, the casting broke loose from the block, thus allowing a direct path to atmosphere for the air under the piston of

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the MSIV. Detailed inspection indicated the cause of the problem to be the length of the bolts used to fasten the casting to the block

--they were too short. A comparison of the thickness of the casting flange through which the bolts passed and associateo lock washers to the length of the bolts, indicated there were only about 3 threads of engagement of each of the carbon steel bolts into the aluminum block. Corrective action involved increasing the length of the bolts

, and inspecting the remaining bolting on the NS-04A manifold and the L bolting on the other three MSIV manifolds. Other problems with short bolts were identified and corrected.

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Maintenance, Construction, and Facilities critiqued this event and their findings are documented in critique number 87-18. Although a

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j point in time was not specifically identified when the short bolts were installed, it was determined to be prior to 1982 and was done independently by I & C technicians. The critique concluded this type of independent action could no 1snger occur based on the controls put into effect since 198 The inspectors observed many of the activities associated with iden-tifying and correcting this problem and concluded licensee corrective actions were thoroug During this report period, the torus water level started and con-tinued to increase because of an unidentified leak from a piping system inside the drywell. Because of concerns that, if the plant continued to operate, the level would reach the maximum value, the licensee planned to drain the toru The NRC inspectors were con-cerned about the acceptability of this action because containment isolation valves that are required to be closed would have to be opened, and it was unclear in the Tech Specs whether or nor the valves could be opene Discussions about the acceptability of this activity ensued with the end result being an agreement that the torus could be drained for eight hours a day for 30 days as long as an individual was stationed at the isolation valves with a "wa l ki e-talkie" to provide for direct contact with the control roo This temporary provision to drain would give the licensee sufficient time to pursue a Tech Spec change to clarify the ambiguit _ _ - _ _ _

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The licensee wrote a- torus drain ' procedure and a safety evaluation which were reviewed by the inspectors and found acceptable. Draining was initiated and. continued for several days until the plant scramme While repairs were being effected, the licensee drained the torus to r. ear the minimum acceptable leve Shortly after re "

start from the trip, it was observed that torus level was again increasing from an unidentified leak in the drywell' and the subject of draining the torus again became an issue. In discussions with the licensee, it was determined that they had not initiated any process to clariiy the Tech Specs regarding this issue nor do they intend t ~

This position is based on their interpretation that the present Tech Specs provide sufficient latitude to allow repositioning' the valves used for draining. At the end of this report period, the issue was still not resolved and will continue to be pursued until a solution '

is reache V-5-167, a Reactor Building Closed Cooling Water system containment isolation valve, failed to operate during this report period. Inves-tigation into the cause of the problem determined that boron crystals had built up along the valve stem through a leaky packing - and the additional resistance offered by this buildup could not be overcome by the valve's motor operato Because of the significant schedular impact of repacking the valve, the licensee made a decision to take other action to ensure valve operability throughout the balance of operating cycle 1 This-action includes partially closing the valve monthly using the manual

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operator and fully closing the valve quarterly using the electric motor operato The valve is scheduled to be repacked in the 12R ,

refueling outage' with Chesterton spring loaded packing. The inspec-tors followed the licensee's troubleshooting efforts and agreed with the problem identification and temporary solutio . Core Spray System II Piping Supports During the outage following the reactor trip on 7/30/87, two Core Spray -I System II pipe supports were inspected and a MNCR generated for each sup-port to document the identified deficiencies. The inspectors reviewed the l MNCRs and associated deviation reports and became concerned because of the types of discrepancies identified and the lack of adequate technical pur-suit of the proble MNCR 87-156 written against support BP-411-R5 identified location discrep-ancies, a broken anchor bolt, and a loose anchor bolt. MNCR 87-157 writ-

ten against support BP-411-R6 identified use of materials not part of the 4 design drawing (extra plate and welds and different type anchor bolts),

location discrepancies, improper clamp, anchor bolt skewness in excess of

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acceptable limits, loose anchor bolts, and an oversized hoie in the base plate with no washer. These two supports are hydraulic snubbers used in the discharge line from the main pump Both of these MNCRs were initially dispositioned to rework and correct the unacceptable deficien-cies. However, based on an analysis performed by Tech Functions, it was determined that system operability was unaffected by the removal of these supports from the analysis and, therefore, the repairs did not need to be made prior to restart of the plan The (2RC inspectors sensed schedular pressure was driving the decision to not repair the supports so asked Tech Functions personnel one key ques-tion: Based on the frequency and types of problems identified with Core Spray system supports during the Bulletin 79-02 and 79-14 reinspection, had all the supports used in the analysis to determine system operability without supports R5 and R6 been inspected and appropriate repairs made?

The response to this question was no -- that several supports used in the analysis were uninspected and were assumed to be installed and functional per original desig The inspectors felt this assumption was w.ithout

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sufficient technical basis and requested the licensee to address the issue

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to assure operability of Core Spray System II. This was reiterated during i

a conference call between NRC Region I management and licensee managemen Licensee . actions involved identifying those supports critical to the analysis and inspecting those that had not previously been inspecte Additionally, repairs were made to R5 and R Upon completion of this activity, it was determined the system was operabl In conclusion, the NRC inspectors felt the technical support associated with these pipe support problems was not sufficient in its dept The initial review appeared to be superficial and driven by schedular press-ure The NRC agreed to grant relief to the licensee for initially defic-ient responses to Bulletins 79-02 and 79-14, and it was expected that a greater degree of sensitivity to operability questions would have been forthcoming. It is expected in the future that when questions of opera-bility are involved, the data used for analyses will reflect actual con-ditions and not assume items that have not been inspected are totally in conformance with original design drawing This matter was re-emphasized in a letter to the licensee from the Director, Division of Reactor Projects, NRC Region I dated August 13, 198 . Drywell Shell Corrosion

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Water leakage f rom the sand cushion drains in bays 11,15, and 19 has been l observe Bays 15 anc 19 f ace the spent fuel pool side of the building I and bay 31 faces directly west, equally between the spent fuel pool and equipment pool. The licensee suspects that there may be leakage either from the equipment pool and/or the spent fuel pool through the stainless steel liner and into the air gap. Plans are to drain, clean, and inspect portions of the equipment pool liner by vacuum box leak testing and liquid penetrant testing.

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Drywell sh' ell thickness measurements were taken during the brief outage that occurred . during this report period and the licensee rsported an

~;. analysis.of these .results indicated no additional thinning has occurre The inspectors continue to follow these and other drywell shell thinning

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23. ' Exit Interview

A summary of the results of- the inspection activities performed during this report period were made at meetings with senior licensee management

,. at the end of,this inspection. .The licensee stated that, of the subjects discussed at the exit interview, no proprietary information was include ~

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